U.S. patent number 7,591,314 [Application Number 10/776,089] was granted by the patent office on 2009-09-22 for measurement-while-fishing tool devices and methods.
This patent grant is currently assigned to Baker Hughes Incorporated. Invention is credited to James W. Anderson, Robbie B. Colbert, Gerald Heisig, Johnny C. Hicks, Blake C. Pizzolato, James A. Sonnier.
United States Patent |
7,591,314 |
Sonnier , et al. |
September 22, 2009 |
**Please see images for:
( Certificate of Correction ) ( Reexamination Certificate
) ** |
Measurement-while-fishing tool devices and methods
Abstract
Methods and devices for sensing operating conditions associated
with downhole, non-drilling operations, including, fishing and
retrieval operations as well as underreaming or casing cutting
operations and the like. A condition sensing device is used to
measure downhole operating parameters, including, for example,
torque, tension, compression, direction of rotation and rate of
rotation. The operating parameter information is then used to
perform the downhole operation more effectively.
Inventors: |
Sonnier; James A. (Houston,
TX), Colbert; Robbie B. (Perdido, AL), Anderson; James
W. (Katy, TX), Heisig; Gerald (Celle, DE),
Pizzolato; Blake C. (Montgomery, TX), Hicks; Johnny C.
(Keller, TX) |
Assignee: |
Baker Hughes Incorporated
(Houston, TX)
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Family
ID: |
32908499 |
Appl.
No.: |
10/776,089 |
Filed: |
February 11, 2004 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20040251027 A1 |
Dec 16, 2004 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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60447771 |
Feb 14, 2003 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
47/00 (20130101); E21B 44/00 (20130101); E21B
31/00 (20130101) |
Current International
Class: |
E21B
31/00 (20060101); E21B 31/18 (20060101) |
Field of
Search: |
;166/297,55.1,277,301,377,380,378,98,99,178,339,117.7,66
;340/853.3,853.4,853.9,853.8,854.2 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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0552087 |
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Jul 1993 |
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EP |
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2231357 |
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Nov 1990 |
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GB |
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2349403 |
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Jan 2000 |
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GB |
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WO03/012250 |
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Feb 2003 |
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WO |
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Primary Examiner: Thompson; Kenneth
Attorney, Agent or Firm: Mossman, Kumar & Tyler, PC
Parent Case Text
This application claims the priority of U.S. Provisional patent
application Ser. No. 60/447,771 filed Feb. 14, 2003.
Claims
What is claimed is:
1. A system for detecting a downhole condition in a wellbore during
a non-drilling wellbore operation, the system comprising: a tool
string formed of a tubular to be disposed within the wellbore; a
fishing device configured to be conveyed into the wellbore using
the tool string; at least one sensor along the tool string for
sensing the downhole condition, the at least one sensor configured
to be conveyed into the wellbore with the fishing device using the
tool string; and a processing section for receiving data relating
to the downhole condition.
2. A method of performing a non-drilling downhole wellbore
operation comprising: integrating a workpiece and a condition
sensing tool into a tool string; disposing the tool string into a
wellbore; actuating the workpiece to conduct a non-drilling
downhole operation; detecting at least one downhole condition with
the condition sensing tool while operating the workpiece; receiving
data relating to the at least one downhole condition within a
processing section of the condition sensing tool; and rotating the
tool string.
3. A system for detecting a downhole condition in a wellbore during
a non-drilling wellbore operation, the system comprising: a tool
string formed of a tubular to be disposed within the wellbore,
wherein the tool string is configured to rotate; a workpiece
configured to be conveyed into the wellbore using the tool string,
the workpiece configured to perform the non-drilling wellbore
operation within the wellbore; at least one sensor along the tool
string for sensing the downhole condition, the condition sensing
tool configured to be conveyed into the wellbore with the workpiece
using the tool string; and a processing section for receiving data
relating to the downhole condition.
4. The system of claim 3, further comprising: a transmitter
associated with the processing section and configured to transmit
the data relating to the downhole condition to the surface.
5. The system of claim 4 wherein the workpiece comprises a cutting
tool.
6. The system of claim 5 wherein the cutting tool comprises an
underreamer.
7. The system of claim 5 wherein the cutting tool comprises a
casing cutter.
8. The system of claim 3, further comprising a power section.
9. The system of claim 1, wherein the transmitter uses mud pulse
telemetry.
10. A system for detecting a downhole condition in a wellbore
during a non-drilling wellbore operation, the system comprising: a
tool string formed of a tubular to be disposed within the wellbore;
a workpiece configured to be conveyed into the wellbore using the
tool string, the workpiece configured to perform the non-drilling
wellbore operation within the wellbore; at least one sensor along
the tool string for sensing the downhole condition, the at least
one sensor being configured to be conveyed into the wellbore with
the workpiece using the tool string a processing section for
receiving data relating to the downhole condition and a transmitter
associated with the processing section and configured to transmit
the data relating to the downhole condition to the surface, wherein
the transmitter uses mud pulse telemetry; wherein the at least one
downhole condition is a condition from the set consisting of
torque, weight, tool string compression, tool string tension, speed
of tool string rotation, vibration, and direction of tool string
rotation.
11. The system of claim 10, further comprising a controller
positioned at the surface that is configured to control the
workpiece.
12. A condition sensing tool for use within a wellbore during a
non-drilling operation to detect at least one downhole condition
within the wellbore, the condition sensing tool being deployable
via a tubular tool string and comprising: an outer housing defining
an axial fluid flowbore therethrough and being coupled to the
tubular tool string; a sensor section formed in the housing; and at
least one sensor in the sensor section for detecting the at least
one non drilling downhole condition from the set of conditions
consisting essentially of torque, weight, tool string compression,
tool string tension, speed of tool string rotation, vibration, and
direction of tool string rotation, wherein the outer housing, the
sensor section, and the at least one sensor are configured to be
conveyed into the wellbore with the tubular tool string; and a
power section within the housing for supplying power to the sensor
section.
13. A condition sensing tool for use within a wellbore during a
non-drilling operation to detect at least one downhole condition
within the wellbore, the condition sensing tool being deployable
via a tubular tool string and comprising: an outer housing defining
an axial fluid flowbore therethrough and being coupled to the
tubular tool string; a sensor section formed in the housing; and at
least one sensor in the sensor section for detecting the at least
one non drilling downhole condition from the set of conditions
consisting essentially of torque, weight, tool string compression,
tool string tension, speed of tool string rotation, vibration, and
direction of tool string rotation, wherein the outer housing, the
sensor section, and the at least one sensor are configured to be
conveyed into the wellbore with the tubular tool string; and a
processing section for receiving data relating to the downhole
condition and transmitting the data to a remote receiver.
14. A method of performing a non-drilling downhole wellbore
operation comprising: integrating a workpiece and a condition
sensing tool into a tool string; disposing the tool string into a
wellbore; actuating the workpiece to conduct a non-drilling
downhole operation; detecting at least one downhole condition with
the condition sensing tool; and wherein a) the workpiece comprises
a fishing tool for engaging a stuck member within the wellbore; b)
the non-drilling downhole operation comprises a fishing operation
to remove a stuck member from the wellbore; and c) the condition
sensing tool detects weight and torque.
15. A method of performing a non-drilling downhole wellbore
operation, comprising: integrating a workpiece and a condition
sensing tool into a tool string formed of a tubular; conveying the
workpiece and the condition sensing tool into a wellbore using the
tool string formed of the tubular; actuating the workpiece to
conduct a non-drilling downhole operation; detecting at least one
down hole condition with the condition sensing tool; and
transmitting information indicative of the downhole condition to a
surface location, wherein: a) the workpiece comprises an anchor
latch; b) the non-drilling downhole operation comprises unthreading
of a threaded connection within the wellbore; and c) the condition
sensing tool detects tool string compression and tool string
tension.
16. A method of performing a non-drilling downhole wellbore
operation comprising: integrating a workpiece and a condition
sensing tool into a tool string; disposing the tool string into a
wellbore; actuating the workpiece to conduct a non-drilling
downhole operation; detecting at least one downhole condition with
the condition sensing tool; and wherein: a) the workpiece comprises
a packer; b) the non-drilling downhole operation comprises
retrieval of the packer from a set position within the wellbore;
and c) the condition-sensing tool detects torque and weight.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The invention relates generally to methods and devices for
detecting wellbore and tool operating conditions while engaged in
fishing or other downhole manipulation operations to remove a
wellbore obstruction or in other non-drilling applications,
especially in very deep and/or deviated wellbores.
2. Description of the Related Art
Devices are known for measurement-while-drilling (MWD) and
logging-while-drilling (LWD) wherein certain borehole conditions
are measured and either recorded within storage media within the
wellbore or transmitted to the surface using encoded transmission
techniques, such a frequency shift keying (FSK). Transmission may
be accomplished via radio waves or fluid pulsing within drilling
mud. The conditions measured typically include temperature, annulus
pressure, drilling parameters, such as weight-on-bit (WOB),
rotational speed of the drill bit and/or the drill string (RPMs),
and the drilling fluid flow rate. An MWD or LWD sub is incorporated
into the drill string above the bottom hole assembly and then
operated during drilling operations. Examples of drilling systems
that utilize MWD/LWD technology are described in U.S. Pat. Nos.
6,233,524 and 6,021,377, both of which are owned by the assignee of
the present invention and are incorporated herein by reference.
Aside from typical drilling operations, there are other situations
where it is helpful to have certain information relating to
operation of the tool that is operating downhole and its
environment. In very deep and/or high angle wellbores, it is
difficult to verify details concerning the operation of the
downhole tools through surface indications alone. For example, if
one were attempting to remove a stuck section of casing in a deep
and/or deviated wellbore using a rotary milling device, it would be
very helpful to be able to measure the amount of torque induced
proximate the milling device. Without an indication of the amount
of torque induced proximate the milling device, the milling string
can be overtorqued at the surface and the string between the
milling tool and the surface will absorb the torque forces without
effectively transmitting them to the milling tool. Overtorquing the
tool string in this situation may lead to a shearing of the tool
string below the surface, thereby creating an obstruction that is
even more difficult to remove.
To the inventors' knowledge, there are no known, acceptable devices
for providing useful downhole operating condition information,
including torque, weight, compression, tension, speed of rotation,
and direction of rotation, in non-drilling situations. Further, the
use of standard MWD tools for such non-drilling applications is
quite expensive. Current MWD tools are designed to obtain
significant amounts of borehole information, much of which is not
relevant outside of a drilling scenario. The devices for collecting
this drilling specific information includes nuclear sensors, such
as gamma ray tools for determining formation density, nuclear
porosity and certain rock characteristics; resistivity sensors for
determining formation resistivity, dielectric constant and the
presence or absence of hydrocarbons; acoustic sensors for
determining the acoustic porosity of the formation and the bed
boundary in formation; and nuclear magnetic resonance sensors for
determining the porosity and other petrophysical characteristics of
the formation. To the inventors' knowledge, there is no known and
acceptable "fit-for-purpose" tool wherein the sensor portion of the
tool may be customized to detect those data that are important to
the job at hand while not detecting irrelevant or less relevant
information.
There is a need for improved devices and methods that are capable
of providing operating condition information to the surface in
non-drilling situations. There is also a need for improved methods
and devices for accomplishing fishing and retrieval-type
operations. Additionally, there is a need for improved methods and
devices for accomplishing other non-drilling applications, such as
underreaming, in-hole casing cutting and the like. The present
invention addresses the problems of the prior art.
SUMMARY OF THE INVENTION
The invention provides methods and devices for sensing operating
conditions associated with downhole, non-drilling operations,
including, fishing, but also with retrieval operations as well as
underreaming or casing cutting operations and the like. In
currently preferred embodiments, a condition sensing device is used
to measure downhole operating parameters, including, for example,
torque, tension, compression, direction of rotation and rate of
rotation. The operating parameter information is then used to
perform the downhole operation more effectively.
In one embodiment, a memory storage medium is contained within the
tool proximate the sensors. The detected information is recorded
and then downloaded after the tool has been removed from the
borehole. In a further embodiment, the detected information is
encoded and transmitted to the surface in the form of a coded
signal. A receiver, or data acquisition system, at the surface
receives the encoded signal and decodes it for use. Means for
transmitting the information to the surface-based receiver include
mud-pulse telemetry and other techniques that are useful for
transmitting MWD/LWD information to the surface. In a further
aspect of the invention, a controller is provided for adjusting the
downhole operation in response to one or more detected operating
conditions.
The invention provides for an inexpensive condition sensing tool
that is useful in a wide variety of situations. The invention also
provides a "fit-for-purpose" tool that may be easily customized to
collect and provide desired operating condition information without
collecting undesired information. In related aspects, the invention
also provides for improved method of conducting non-drilling
operations within a borehole, including fishing operations, wherein
measured downhole operating condition information is used to
improve the non-drilling operation and make it more effective.
BRIEF DESCRIPTION OF THE DRAWINGS
The advantages and further aspects of the invention will be readily
appreciated by those of ordinary skill in the art as the same
becomes better understood by reference to the following detailed
description when considered in conjunction with the accompanying
drawings in which like reference characters designate like or
similar elements throughout the several figures of the drawing and
wherein:
FIG. 1 is a schematic, cross-sectional view of an exemplary
wellbore employing a tool and tool assembly constructed in
accordance with the present invention.
FIG. 2 is an isometric view, partially in cross-section, of an
exemplary condition-sensing tool constructed in accordance with the
present invention.
FIG. 3 is a side cross-sectional, schematic depiction of an
illustrative fishing application wherein a section of production
tubing and packer are being removed from a borehole, in accordance
with the present invention.
FIG. 4 is a side cross-sectional, schematic depiction of an
illustrative backoff operation conducted in accordance with the
present invention.
FIG. 5 is a schematic side, cross-sectional view of an illustrative
casing cutting arrangement conducted in accordance with the present
invention.
FIG. 6 is a schematic side, cross-sectional view of an illustrative
underreaming arrangement conducted in accordance with the present
invention.
FIG. 7 is a schematic side, cross-sectional view of an illustrative
fishing application for removal of a packer from within a borehole,
conducted in accordance with the present invention.
FIG. 8 is a schematic side, cross-sectional view of an illustrative
pilot milling application conducted in accordance with the present
invention.
FIG. 9 is a schematic side, cross-sectional view of an illustrative
washover retrieval operation for retrieval of a stuck bottom hole
assembly, conducted in accordance with the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
FIG. 1 is a schematic drawing depicting, in general terms, the
structure and operation of a tool and tool assembly constructed in
accordance with the present invention as well as methods and
systems in accordance with the present invention. These tools, tool
assemblies, systems and methods may be referred to herein for
shorthand convenience as "measurement-while-fishing" systems,
although this term is not intended to limit the invention to
"fishing" applications. Those of skill in the art will understand
that there are, in fact, numerous non-drilling applications for the
systems, methods and devices of the present invention.
FIG. 1 shows a rig 10 for a hydrocarbon well 12. It will be
understood that, while a land-based rig 10 is shown, the systems
and methods of the present invention are also applicable to
offshore rigs, platforms and floating vessels. From the rig 10, a
borehole 12 extends downwardly from the surface 14. A tool string
16 is shown disposed within the borehole 12. The tool string 16 may
comprise a string of drill pipe sections, production tubing
sections or coiled tubing. The tool string 16 is tubular and
defines a bore therein through which drilling mud or other fluid
may be pumped. Although not depicted in FIG. 1, the rig 10 includes
means for pumping drilling fluid or other fluid into the tool
string 16 as well as means for rotating the tool string 16 within
the borehole 12. At the lower end of the tool string 16 there is
secured a condition sensing tool 18, the lower end of which is, in
turn, affixed to a workpiece 20. The workpiece 20 refers generally
to a tool or device that is performing a function within the
borehole 12 and for which certain operational data is desired at
the surface 14. As will be understood by reference to the exemplary
embodiments described shortly, the workpiece 20 may comprise a
fishing device, such as a jarring tool or latching mechanism, or a
cutting tool, such as an underreamer or casing cutter, or other
device.
It is noted that the borehole 12 may extend rather deeply below the
surface (i.e., 30,000 feet or more) and, while shown in FIG. 1 to
be substantially vertically oriented, may actually be deviated or
even horizontal along some of its length. At the surface 14 is a
data acquisition system 22 and a controller 24. An operator at the
surface typically controls operation of the workpiece 20 by
adjusting such parameters as weight on the workpiece, fluid flow
through the tool string 16, rate and direction of rotation of the
tool string 16 (if any) and so forth.
Referring now to FIG. 2, there is shown in cross-section details
for the construction and operation of an exemplary
condition-sensing tool 18 constructed in accordance with the
present invention. The tool 18 includes a generally cylindrical
outer housing 26 having axial ends 28, 30 that are configured for
threaded engagement to adjoining portions of the tool string 16 and
the workpiece 20. The housing 26 defines a flowbore 32 therethrough
to permit the passage of drilling fluid or other fluid. One or more
wear pads 34 may be circumferentially secured about the tool 18 to
assist in protection of the tool 18 from damage caused by borehole
friction and engagement. The tool 18 includes a sensor section 36
having a plurality of condition sensors mounted thereupon. In the
exemplary tool 18 shown, the sensor section 36 includes a weight
sensor 38 that is capable of determining the amount of weight
exerted by the tool string 16 upon the workpiece 20 and a torque
gauge 40 that is capable of measuring torque exerted upon the
workpiece 20 by rotation of the tool string 16. Additionally, the
sensor section 36 includes an angular bending gauge 42, which is
capable of measuring angular deflection or bending forces within
the tool string 16. Additionally, the sensor section 36 includes an
annulus pressure gauge 44, which measures the fluid pressure within
the annulus created between the housing 26 and the borehole 12. A
bore pressure gauge 46 measures the fluid pressure within the bore
32 of the tool 18. While the operable electrical interconnections
for each of these sensors is not illustrated in FIG. 2, such are
well known to those of skill in the art and, thus, will not be
described in detail herein. An accelerometer 48 is illustrated as
well that is operable to determine acceleration of the tool 18 in
an axial, lateral or angular direction. Through each of the above
described sensors, the sensor section 36 obtains and generates data
relating to the operating parameters of the workpiece 20.
In a currently preferred embodiment, the condition sensing tool 18
may comprise portions of a CoPilot.RTM. MWD tool, which is
available commercially from the INTEQ division of Baker Hughes,
Incorporated, Houston, Tex., the assignee of the present
application. It is noted that the condition sensing tool 18 does
not require, and typically will not include, those components and
assemblies that are useful primarily or only in a drilling
situation. These would include, for example, gamma count devices
and directional sensors used to orient the tool with respect to the
surrounding formation. This greatly reduces the cost and complexity
of the tool 18 in comparison to traditional MWD or LWD tools. It is
intended that the tool 18 be a "fit-for-purpose" tool that is
constructed to have those sensors that are desired for a given job
but not others that are not required. As a result, the cost and
complexity of the tool 18 is minimized.
The tool 18 also includes a processing section 50 and a power
section 52. The processing section 50 is operable to receive data
concerning the operating conditions sensed by the sensor section 36
and to store and/or transmit the data to a remote receiver, such as
the receiver or data acquisition system 22 located at the surface
14. The processing section 50 preferably includes a digital signal
processor 53 and storage medium, shown at 54, which are operably
interconnected with the sensor section 36 to store data obtained
from the sensor section 36. The processor 53 (also referred to as
the "control unit" or a "processing unit") includes one or more
microprocessor-based circuits to process measurements made by the
sensors in the drilling assembly at least in part, downhole during
drilling of the wellbore.
The processor section 50 also includes a data transmitter,
schematically depicted at 56. The data transmitter 56 may comprise
a mud pulse transmitter, of a type known in the art, for
transmitting encoded data signals to the surface 14 using mud pulse
telemetry. The data transmitter 56 may also comprise other
transmission means known in the art for transmitting such data to
the surface.
The power section 52 houses a power source 58 for operation of the
components within the processor section 50 and the sensor section
36. In a currently preferred embodiment, the power source 58 is a
"mud motor" mechanism that is actuated by the flow of drilling
fluid or another fluid downward through the tool string 16 and
through the bore 32 of the tool 18. Such mechanisms utilize a
turbine that is rotated by a flow of fluid, such as drilling mud,
to generate electrical power. An example of a suitable mechanism of
this type is the power source assembly within the 43/4''
CoPilot.RTM. tool that is sold commercially by Baker Hughes INTEQ.
Other acceptable power sources may also be employed, such as
batteries where, for example, fluid in not flowed during the
particular downhole operation being performed.
A number of exemplary methods and arrangements for implementing the
present invention will now be described in order to illustrate the
systems and method of the invention. FIG. 3 depicts a situation
wherein it is necessary to fish a section of production tubing 60
and a retrievable packer 62 out of the borehole 12. This type of
fishing operation may be necessary where the production tubing 60
has developed a breach above the location of the packer 62, and the
packer 62 cannot be released using its intended release mechanism.
In FIG. 3, the borehole 12 is shown lined with casing 64, and the
packer 62 is sealed against the inner wall of the casing 64. The
upper end 66 of the production tubing section 60 has been cut off
in an uneven fashion and the upper portion of the production tubing
string leading to the surface 14 has been removed.
A tool string 16, which in this instance may comprise a string of
production tubing or coiled tubing, is then lowered into the
borehole 12 as shown in FIG. 3. The condition sensing tool 18 is
secured to the lower end of the tool string 18. In this
arrangement, the tool 18 is configured to have at least a weight
sensor 38 and torque gauge or sensor 40. Affixed to the lower end
of the tool 18 is an engagement device 68, which serves as the
workpiece 20. The engagement device 68 is a fishing tool, of a type
known in the art, which is configured to engage the upper end 66 of
the production tubing section 60. Then, by pulling upwardly upon,
jarring, pressuring up within, and/or by rotating the tool string
16, the production tubing section 60 and the packer 62 are removed
from the borehole 12.
In operation, the weight sensor 38 of the tool 18 detects the
amount of upward force exerted upon the engagement device 68 from
upward pull on the tool string 16. If rotation of the tool string
16 is applied in an attempt to remove the tubing string section 60
and packer 62, then the torque gauge 40 will detect the amount of
torque from this rotation that is actually felt at the engagement
tool 68. Alternatively, if the tool string 16 is pressured up in
order to help release the tubing string section 60 and packer 62,
detection of bore pressure and annulus pressure would be desirable.
This data is then either stored or transmitted to the surface 14 so
that an operator can detect whether there is a significant
discrepancy between the upward or rotational force being applied at
the surface and the forces being received proximate the workpiece
20. A significant difference may be indicative of a problem that
prevents full transmission of such forces, such as an obstruction
in the annulus or the tool string 16 being grounded against the
borehole 12 in a deviated and/or extremely deep portion of the
borehole 12.
Referring now to FIG. 4, there is shown an illustrative anchor
latch or threaded arrangement wherein the utility of the devices
and methods of the present invention is shown for performing
disconnection of threaded components within the borehole 12. In
this instance, a packer element 62 is shown secured against the
casing 64 of the borehole 12 and retains a production tubing
portion 66 that includes a lower tubing section 69 that is secured
by threaded connection 70 to an upper tubing section 72. The upper
tubing section 72 has been cut away as with the production tubing
section 60 described earlier. An engagement tool 74, herein serving
as the workpiece 20, is secured to the condition sensing tool 18
and is configured to fixedly engage the upper end 76 of the upper
tubing section 72. Such an engagement tool 74 is known in the art.
It is desired to unthread the threaded connection 70 so that the
upper tubing string section can be removed from the borehole 12 and
replaced with another tubing string section which can then be
threadedly engaged with the lower tubing section 69 to reestablish
production within the borehole 12. Unthreading of the threaded
connection 70 depends upon lifting up on the tool string 16 until
the compression force, or weight, upon the threaded connection 70
is essentially zero. Otherwise, the threaded connection 70 will be
difficult, if not impossible to unthread. Attempting to do so may,
in fact, damage the thread, making it impossible to attach another
production tubing section later. Conversely, too much lifting up on
the tool string 16 will also cause the threaded connection 70 to be
difficult or impossible to unthread though rotation of the tool
string 16. Therefore, it is important to be able to sense and
determine the amount of tension and compression that is felt
proximate the engagement tool 74 with some accuracy. Therefore, the
condition sensing tool 18 is configured to sense, at least, weight
and torque. In operation, the engagement tool 74 is latched onto
the upper section 72 and the operator pulls upward or slacks off on
the tool string 16 until the weight reading is essentially zero,
indicating that unthreading of the threaded connection 70 may
begin. The tool string 16 is then rotated in the direction
necessary to unthread the connection 70. Torque readings from the
tool 18 will indicate whether there is a problem in transmitting
the rotational forces from rotating the tool string 16 to the
engagement tool 74.
FIG. 5 illustrates a situation wherein a portion of wellbore casing
64 is being cut by a casing cutter 80. Those of skill in the art
will understand that it could as easily apply to the cutting of
production tubing. The casing cutter 80 is secured to the lower end
of the condition sensing tool 18 and includes, essentially a
central tubular body 82 with a pair of radially extending cutters
84. Such cutting tools are well known in the art and are used only
in order to illustrate the invention and, therefore, will not be
described in detail herein. The casing cutter 80 is shown cutting
through the casing 64 and into the surrounding formation 86 by
cutters 84. Because the casing cutter 80 is rotated by rotation of
the tool string 16, it is important to know the direction of
rotation, the speed of rotation (RPM), as well as the weight on the
casing cutter 80. In operation, the tool string 16 is rotated to
cause the casing cutter 80 to cut the casing 64 to form an opening
88. The tool 18 is configured to sense at least the speed (RPM) and
direction of rotation proximate the casing cutter 80 to ensure that
the opening 88 is properly cut. Measurements of the torque applied
to the casing cutter 80 and weight upon the casing cutter 80 are
also important and are preferably sensed by the tool 18.
Referring now to FIG. 6, an underreaming situation is illustrated
that incorporates the devices and methods of the present invention.
An underreamer device 90 is affixed to the lower end of the tool
18. The underreamer device 90, as is known in the art, includes a
tubular body 92 with a plurality of underreamer arms 94 which are
pivotally connected to the body 92 and move radially outwardly to
cut the formation 86 when the underreamer body 92 is rotated about
its longitudinal axis. Underreaming is used when it is desired to
enlarge the diameter of the borehole 12 at a certain point. In an
underreamer operation, it is important to monitor the torque forces
proximate the underreamer 90. Thus, the tool 18 is configured to at
least sense torque forces proximate the underreamer 90. Preferably,
the tool 18 is also configured to sense weight, rate of rotation
(RPM), and direction of rotation.
Turning now to FIG. 7, there is shown an arrangement wherein a
packer 100 is being retrieved from a set position within the
borehole 12. The condition sensing tool 18 is secured to the lower
end of the tool string 16, and an engagement tool 102 is affixed to
the lower end of the condition sensing tool 18. The engagement tool
102 is configured to latch onto the packer 100 and unset it for
removal from the borehole 12. The tool string 16 is lowered into
the borehole 12 until the engagement tool 102 becomes securely
latched onto the packer 100. The packer 100 is typically released
from engagement with the wall of the borehole 12 by pulling
upwardly on the tool string 16 and/or by rotating the tool string
16 so as to apply tension and torque to the packer 100. In this
instance, then, the tool 18 should be configured to measure at
least tension/compression (weight) and torque proximate the packer
100.
FIG. 8 illustrates an exemplary pilot milling arrangement wherein a
rotary pilot mill 104 is secured to the condition sensing tool 18
and tool string 16. The mill 104 has a generally cylindrical
central body 106 with a number of radially-extending milling blades
108. The body 106 presents a nose section 110. The mill 104 is
shown in contact with the upper end of a tubular member 112 that
has become stuck in the borehole 12. It is desired to mill away the
tubular member 112 by rotation of the mill 104 so as to cause the
milling blades 108 to cut the tubular member 112 away. Thus, the
mill 104 is set down atop the tubular member 112 so that the nose
110 is inserted into the tubular member 112 and the blades 108
contact the upper end of the tubular member 12. During operation,
drilling mud is circulated down through the tool string 16, tool 18
and mill 104. The drilling mud exits the mill 104 proximate the
location where the blades 108 contact the tubular member 112 and
serves to lubricate the cutting process and/or provide a means to
circulate cuttings to the surface via the wellbore fluid in the
annulus.
In milling operations such as the one shown in FIG. 8, it is
helpful to be able to detect the torque forces, direction of
rotation, weight (i.e., axial tension and/or compression forces
exerted on the mill by the tool string 16), and speed of rotation
for the mill 104. Thus, the tool 18 should be configured to at
least detect these downhole operating parameters. Additionally, the
amount of bounce of the mill 104 may be determined by incorporating
a vibration sensor (not shown), of a type known in the art, into
the sensor section 36 of the tool 18. The sensed information is
then used to make adjustments to the milling procedure (i.e., a
change in RPM, setting down on or lifting up on the mill) to
improve the milling procedure.
FIG. 9 illustrates a washover retrieval operation incorporating
devices and method of the present invention. In this instance, a
bottom hole assembly (BHA) 118 has become stuck in the borehole 12.
The BHA 118 includes a drill bit 120 and drill pipe section 122
extending upwardly therefrom. The drill pipe section 122 is a stub
portion of the drill pipe string that remains after the rest of the
drill string has been cut away and removed. The BHA 118 is but one
example of a component that might become stuck in the wellbore.
Other components that might become lodged or stuck in the borehole
12 include screens, liners, drill pipe sections, tubing sections
and so forth.
Secured to the lower end of the tool string 16 is the condition
sensing tool 18 and a washover tool 124, which serves as the
workpiece 20. The washover tool 124 includes a rotary shoe 126 with
annular cutting edge 128 that is designed for cutting away the
formation around the stuck BHA 118. In this way the stuck component
118 is washed over and easier to remove. In this operation, it is
desirable to know, in particular, the torque forces experienced
proximate the washover tool 124. Thus, the condition sensing tool
18 should be configured to sense at least torque forces.
Preferably, the tool 18 is also configured to sense RPM and
direction of rotation in order to help prevent inadvertent twisting
off of or damage to the washover tool 124 or to the stuck
component.
It is noted that the data acquisition system 22 preferably includes
a graphical display, 23 in FIG. 1, of a type known in the art,
thereby permitting a human operator to observe indications of
downhole operating conditions and make adjustments to the downhole
operation (i.e., by adjusting the rate of rotation or set down
weight) in response thereto. The effect of the adjustment will be
detected by the downhole sensors of the tool 18 and then
transmitted to the surface 14 where it will be received by the data
acquisition system 22. Thus, it can be seen that a closed-loop
system is provided for control of non-drilling applications based
upon sensed data.
It is further noted that the display and data acquisition system 22
may comprise a suitably programmed personal computer, as opposed to
the "rigfloor" displays that are associated with MWD and LWD
systems. Because there are fewer and less complex parameters to
measure and monitor than with a typical MWD or LWD system, a less
complex and expensive display and acquisition system is
required.
In a further aspect of the invention, automated or semi-automated
control of the non-drilling processes is possible utilizing a
closed loop system. The processor 53 processes measurements made by
the sensors in the condition sensing tool 18, at least in part,
downhole during operations within the wellbore 12. The processed
signals or the computed results are transmitted to the surface 14
by the transmitter 56 of the condition-sensing tool 18. These
signals or results are received at the surface 14 by the data
acquisition system 22 and provided to the controller 24. The
controller 24 then controls downhole operations in response to the
signals or results provided to it.
The processor 53 may also control the operation of the sensors and
other devices in the tool string 16. The processor 53 within the
tool 18 may also process signals from the various sensors in the
condition sensing tool 18 and also control their operation. The
processor 53 also can control other devices associated with the
tool 18, such as the devices casing cutter 80 or the underreamer
90. A separate processor may be used for each sensor or device.
Each sensor may also have additional circuitry for its unique
operations. The processor 53 preferably contains one or more
microprocessors or micro-controllers for processing signals and
data and for performing control functions, solid state memory units
for storing programmed instructions, models (which may be
interactive models) and data, and other necessary control circuits.
The microprocessors control the operations of the various sensors,
provide communication among the downhole sensors and may provide
two-way data and signal communication between the tool 18 and the
surface 14 equipment via two-way mud pulse telemetry.
The surface controller 24 receives signals from the downhole
sensors and devices and processes such signals according to
programmed instructions provided to the controller 24. The
controller 24 displays desired drilling parameters and other
information on a display/monitor 23 that is utilized by an operator
to control the drilling operations. The controller 24 preferably
contains a computer, memory for storing data, recorder for
recording data and other necessary peripherals. The controller 24
may also include a simulation model and processes data according to
programmed instructions. The controller 24 may also be adapted to
activate alarms when certain unsafe or undesirable operating
conditions occur.
While, in the described embodiments, the condition sensing tool 18
is shown to be directly connected to the workpiece 20, this may not
always be so. It is possible that a cross-over tool or some other
component may be secured intermediately between the workpiece 20
and the tool 18.
The foregoing description is directed to particular embodiments of
the present invention for the purpose of illustration and
explanation. It will be apparent, however, to one skilled in the
art that many modifications and changes to the embodiment set forth
above are possible without departing from the scope and the spirit
of the invention.
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